1. Field of the Invention
This invention relates to conventional and/or managed pressure drilling from a floating rig.
2. Description of the Related Art
Rotating control devices (RCDs) have been used in the drilling industry for drilling wells. An internal sealing element fixed with an internal rotatable member of the RCD seals around the outside diameter of a tubular and rotates with the tubular. The tubular may be a drill string, casing, coil tubing, or any connected oilfield component. The tubular may be run slidingly through the RCD as the tubular rotates, or when the tubular is not rotating. Examples of some proposed RCDs are shown in U.S. Pat. Nos. 5,213,158; 5,647,444 and 5,662,181.
RCDs have been proposed to be positioned with marine risers. An example of a marine riser and some of the associated drilling components is proposed in U.S. Pat. No. 4,626,135. U.S. Pat. No. 6,913,092 proposes a seal housing with a RCD positioned above sea level on the upper section of a marine riser to facilitate a mechanically controlled pressurized system. U.S. Pat. No. 7,237,623 proposes a method for drilling from a floating structure using an RCD positioned on a marine riser. Pub. No. US 2008/0210471 proposes a docking station housing positioned above the surface of the water for latching with an RCD. U.S. Pat. Nos. 6,470,975; 7,159,669; and 7,258,171 propose positioning an RCD assembly in a housing disposed in a marine riser. An RCD has also been proposed in U.S. Pat. No. 6,138,774 to be positioned subsea without a marine riser.
U.S. Pat. Nos. 3,976,148 and 4,282,939 proposes methods for determining the flow rate of drilling fluid flowing out of a telescoping marine riser that moves relative to a floating vessel heave. U.S. Pat. No. 4,291,772 proposes a method and apparatus to reduce the tension required on a riser by maintaining a pressure on a lightweight fluid in the riser over the heavier drilling fluid.
Latching assemblies have been proposed in the past for positioning an RCD. U.S. Pat. No. 7,487,837 proposes a latch assembly for use with a riser for positioning an RCD. Pub. No. US 2006/0144622 proposes a latching system to latch an RCD to a housing. Pub. No. US 2009/0139724 proposes a latch position indicator system for remotely determining whether a latch assembly is latched or unlatched.
In more recent years, RCDs have been used to contain annular fluids under pressure, and thereby manage the pressure within the wellbore relative to the pressure in the surrounding earth formation. In some circumstances, it may be desirable to drill in an underbalanced condition, which facilitates production of formation fluid to the surface of the wellbore since the formation pressure is higher than the wellbore pressure. U.S. Pat. No. 7,448,454 proposes underbalanced drilling with an RCD. At other times, it may be desirable to drill in an overbalanced condition, which helps to control the well and prevent blowouts since the wellbore pressure is greater than the formation pressure. While Pub. No. US 2006/0157282 generally proposes Managed Pressure Drilling (MPD), International Pub. No. WO 2007/092956 proposes MPD with an RCD. MPD is an adaptive drilling process used to control the annulus pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the hydraulic annulus pressure profile accordingly.
One equation used in the drilling industry to determine the equivalent weight of the mud and cuttings in the wellbore when circulating with the rig mud pumps on is:Equivalent Mud Weight(EMW)=Mud Weight Hydrostatic Head+Δ Circulating Annulus Friction Pressure(AFP)This equation would be changed to conform the units of measurements as needed.In one variation of MPD, the above Circulating Annulus Friction Pressure (AFP), with the rig mud pumps on, is swapped for an increase of surface backpressure, with the rig mud pumps off, resulting in a Constant Bottomhole Pressure (CBHP) variation of MPD, or a constant EMW, whether the mud pumps are circulating or not. Another variation of MPD is proposed in U.S. Pat. No. 7,237,623 for a method where a predetermined column height of heavy viscous mud (most often called kill fluid) is pumped into the annulus. This mud cap controls drilling fluid and cuttings from returning to surface. This pressurized mud cap drilling method is sometimes referred to as bull heading or drilling blind.
The CBHP MPD variation is achieved using non-return valves (e.g., check valves) on the influent or front end of the drill string, an RCD and a pressure regulator, such as a drilling choke valve, on the effluent or back return side of the system. One such drilling choke valve is proposed in U.S. Pat. No. 4,355,784. A commercial hydraulically operated choke valve is sold by M-I Swaco of Houston, Tex. under the name SUPER AUTOCHOKE. Also, Secure Drilling International, L.P. of Houston, Tex., now owned by Weatherford International, Inc., has developed an electronic operated automatic choke valve that could be used with its underbalanced drilling system proposed in U.S. Pat. Nos. 7,044,237; 7,278,496; 7,367,411 and 7,650,950. In summary, in the past, an operator of a well has used a manual choke valve, a semi-automatic choke valve and/or a fully automatic choke valve for an MPD program.
Generally, the CBHP MPD variation is accomplished with the drilling choke valve open when circulating and the drilling choke valve closed when not circulating. In CBHP MPD, sometimes there is a 10 choke-closing pressure setting when shutting down the rig mud pumps, and a 10 choke-opening setting when starting them up. The mud weight may be changed occasionally as the well is drilled deeper when circulating with the choke valve open so the well does not flow. Surface backpressure, within the available pressure containment capability rating of an RCD, is used when the pumps are turned off (resulting in no AFP) during the making of pipe connections to keep the well from flowing. Also, in a typical CBHP application, the mud weight is reduced by about 0.5 ppg from conventional drilling mud weight for the similar environment. Applying the above EMW equation, the operator navigates generally within a shifting drilling window, defined by the pore pressure and fracture pressure of the formation, by swapping surface backpressure, for when the pumps are off and the AFP is eliminated, to achieve CBHP.
The CBHP variation of MPD is uniquely applicable for drilling within narrow drilling windows between the formation pore pressure and fracture pressure by drilling with precise management of the wellbore pressure profile. Its key characteristic is that of maintaining a constant effective bottomhole pressure whether drilling ahead or shut in to make jointed pipe connections. CBHP is practiced with a closed and pressurizable circulating fluids system, which may be viewed as a pressure vessel. When drilling with a hydrostatically underbalanced drilling fluid, a predetermined amount of surface backpressure must be applied via an RCD and choke manifold when the rig's mud pumps are off to make connections.
While making drill string or other tubular connections on a floating rig, the drill string or other tubular is set on slips with the drill bit lifted off the bottom. The mud pumps are turned off. During such operations, ocean wave heave of the rig may cause the drill string or other tubular to act like a piston moving up and down within the “pressure vessel” in the riser below the RCD, resulting in fluctuations of wellbore pressure that are in harmony with the frequency and magnitude of the rig heave. This can cause surge and swab pressures that will effect the bottom hole pressures and may in turn lead to lost circulation or an influx of formation fluid, particularly in drilling formations with narrow drilling windows. Annulus returns may be displaced by the piston effect of the drill string heaving up and down within the wellbore along with the rig.
The vertical heave caused by ocean waves that have an average time period of more than 5 seconds have been reported to create surge and swab pressures in the wellbore while the drill string is suspended from the slips. See GROSSO, J. A., “An Analysis of Well Kicks on Offshore Floating Drilling Vessels,” SPE 4134, October 1972, pages 1-20, © 1972 Society of Petroleum Engineers. The theoretical surge and swab pressures due to heave motion may be calculated using fluid movement differential equations and average drilling parameters. See BOURGOYNE, J R., ADAM T., et al, “Applied Drilling Engineering,” pages 168-171, © 1991 Society of Petroleum Engineers.
In benign seas of less than a few feet of wave heave, the ability of the CBHP MPD method to maintain a more constant equivalent mud weight is not substantially compromised to a point of non-commerciality. However, in moderate to rough seas, it is desirable that this technology gap be addressed to enable CBHP and other variations of MPD to be practiced in the world's bodies of water where it is most needed, such as deep waters where wave heave may approach 30 feet (9.1 m) or more and where the geologic formations have narrow drilling windows. A vessel or rig heave of 30 feet (peak to valley and back to peak) with a 6⅝ inch (16.8 cm) diameter drill string may displace about 1.3 barrels of annulus returns on the heave up, and the same amount on heave down. Although the amount of fluid may not appear large, in some wellbore geometries it may cause pressure fluctuations up to 350 psi.
Studies show that pulling the tubular with a velocity of 0.5 m/s creates a swab effect of 150 to 300 psi depending on the bottomhole assembly, casing, and drilling fluid configuration. See WAGNER, R. R. et al., “Surge Field Tests Highlight Dynamic Fluid Response,” SPE/IADC 25771, February 1993, pages 883-892, © 1993 SPE/IADC Drilling Conference. One deepwater field in the North Sea reportedly faced heave effects between 75 to 150 psi. See SOLVANG, S. A. et al., “Managed Pressure Drilling Resolves Pressure Depletion Related Problems in the Development of the HPHT Kristin Field,” SPE/IADC 113672, January 2008, pages 1-9, © 2008 IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition. However, there are depleted reservoirs and deepwater prospects, such as in the North Sea, offshore Brazil, and elsewhere, where the pressure fluctuation from wave heaving must be lowered to 15 psi to stay within the narrow drilling window between the fracture and the pore pressure gradients. Otherwise, damage to the formation or a well kick or blow out may occur.
The problem of maintaining a bottomhole pressure (BHP) within acceptable limits in a narrow drilling window when drilling from a heaving Mobile Offshore Drilling Unit (MODU) is discussed in RASMUSSEN, OVLE SUNDE et al, “Evaluation of MPD Methods for Compensation of Surge-and-Swab Pressures in Floating Drilling Operations,” IADC/SPE 108346, March 2007, pages 1-11, © 2007 UDC/SPE Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition. One proposed solution when using drilling fluid with density less than the pore pressure gradient is a continuous circulation method in which drilling fluid is continuously circulated through the drill string and the annulus during tripping and drill pipe connection. An identified disadvantage with the method is that the flow rate must be rapidly and continuously adjusted, which is described as likely to be challenging. Otherwise, fracturing or influx is a possibility. Another proposed solution using drilling fluid with density less than the pore pressure gradient is to use an RCD with a choke valve for back pressure control. However, again a rapid system response is required to compensate for the rapid heave motions, which is difficult in moderate to high heave conditions and narrow drilling windows.
A proposed solution when using drilling fluid with density greater than the pore pressure is a dual gradient drilling fluid system with a subsea mud lift pump, riser, and RCD. Another proposed solution when using drilling fluid with density greater than the pore pressure is a single gradient drilling fluid system with a subsea mud lift pump, riser, and RCD. A disadvantage with both methods is that a rapid response is required at the fluid level interface to compensate for pressure. Subsea mud lift systems utilizing only an adjustable mud/water or mud/air level in the riser will have difficulty controlling surge and swab effects. Another disadvantage is the high cost of a subsea pump operation.
The authors in the above IADC/SPE 108346 technical paper conclude that given the large heave motion of the MODU (±2 to 3 m), and the short time between surge and swab pressure peaks (6 to 7 seconds), it may be difficult to achieve complete surge and swab pressure compensation with any of the proposed methods. They suggest that a real-time hydraulics computer model is required to control wellbore pressures during connections and tripping. They propose that the capability of measuring BHP using a wired drill string telemetry system may make equivalent circulating density control easier, but when more accurate control of BHP is required, the computer model will be needed to predict the surge and swab pressure scenarios for the specific conditions. However, such a proposed solution presents a formidable task given the heave intervals of less than 30 seconds, since even programmable logic controller (PLC) controlled chokes consume that amount of time each heave direction to receive measurement while drilling (MWD) data, interpreting it, instructing a choke setting, and then reacting to it.
International Pub. No. WO 2009/123476 proposes that a swab pressure may be compensated for by increasing the opening of a subsea bypass choke valve to allow hydrostatic pressure from a subsea lift pump return line to be applied to increase pressure in the borehole, and that a surge pressure may be compensated for by decreasing the opening of the subsea bypass choke valve to allow the subsea lift pump to reduce the pressure in the borehole. The '476 publication admits that compensating for surge and swab pressure is a challenge on a MODU, and it proposes that its method is feasible if given proper measurements of the rig heave motion, and predictive control. However, accurate measurements are difficult to obtain and then respond to, particularly in such a short time frame. Moreover, predictive control is difficult to achieve, since rogue waves or other unusual wave conditions, such as induced by bad weather, cannot be predicted with accuracy. U.S. Pat. No. 5,960,881 proposes a system for reducing surge pressure while running a casing liner.
Wave heave induced pressure fluctuations also occur during tripping the drill string out of and returning it to the wellbore. When surface backpressure is being applied while tripping from a floating rig, such as during deepwater MPD, each heave up is an additive to the tripping out speed, and each heave down is an additive to the tripping in speed. Whether tripping in or out, these heave-related accelerations of the drill string must be considered. Often, the result is slower than desired tripping speeds to avoid surge-swab effects. This can create significant delays, particularly with deepwater rigs commanding rental rates of $500,000 per day.
The problem of maintaining a substantially constant pressure may also exist in certain applications of conventional drilling with a floating rig. In conventional drilling in deepwater with a marine riser, the riser is not pressurized by mechanical devices during normal operations. The only pressure induced by the rig operator and contained by the riser is that generated by the density of the drilling mud held in the riser (hydrostatic pressure). A typical marine riser is 21¼ inches (54 cm) in diameter and has a maximum pressure rating of 500 psi. However, a high strength riser, such as a 16 inch (40.6 cm) casing with a pressure rating around 5000 psi, known as a slim riser, may be advantageously used in deepwater drilling. A surface BOP may be positioned on such a riser, resulting in lower maintenance and routine stack testing costs.
To circulate out a kick and also during the time mud density changes are being made to get the well under control, the drill bit is lifted off bottom and the annular BOP closed against the drill string. The annular BOP is typically located over a ram-type BOP. Ram type blow out preventers have also been proposed in the past for drilling operations, such as proposed in U.S. Pat. Nos. 4,488,703; 4,508,313; 4,519,577; and 5,735,502. As with annular BOPs, drilling must cease when the internal ram BOP seal is closed or sealed against the drill string, or seal wear will occur. When floating rigs are used, heave induced pressure fluctuations may occur as the drill string or other tubular moves up and down notwithstanding the seal against it from the annular BOP. The annular BOP is often closed for this purpose rather than the ram-type BOP in part because the annular BOP seal inserts can be more easily replaced after becoming worn. The heave induced pressure fluctuations below the annular BOP seal may destabilize an un-cased hole on heave down (surge), and suck in additional influx on heave up (swab).
There appears to be a general consensus that the use of deepwater floating rigs with surface BOPs and slim risers presents a higher risk of the kick coming to surface before a BOP can be closed. With the surface BOP annular seal closed, it sometimes takes hours to circulate out riser gas. Significant heaving on intervals such as 30 seconds (peak to valley and back to peak) may cause or exacerbate many time consuming problems and complications resulting therefrom, such as (1) rubble in the wellbore, (2) out of gauge wellbore, and (3) increased quantities of produced-to-surface hydrocarbons. Wellbore stability may be compromised.
Drill string motion compensators have been used in the past to maintain constant weight on the drill bit during drilling in spite of oscillation of the floating rig due to wave motion. One such device is a bumper sub, or slack joint, which is used as a component of a drill string, and is placed near the top of the drill collars. A mandrel composing an upper portion of the bumper sub slides in and out of a body of the bumper sub like a telescope in response to the heave of the rig, and this telescopic action of the bumper sub keeps the drill bit stable on the wellbore during drilling. However, a bumper sub only has a maximum 5 foot (1.5 m) stroke range, and its 37 foot (11.3 m) length limits the ability to stack bumper subs in tandem or in triples for use in rough seas.
Drill string heave compensator devices have been used in the past to decrease the influence of the heave of a floating rig on the drill string when the drill bit is on bottom and the drill string is rotating for drilling. The prior art heave compensators attempt to keep a desired weight on the drill bit while the drill bit is on bottom and drilling. A passive heave compensator known as an in-line compensator may consist of one or more hydraulic cylinders positioned between the traveling block and hook, and may be connected to the deck-mounted air pressure vessels via standpipes and a hose loop, such as the Shaffer Drill String Compensator available from National Oilwell Varco of Houston, Tex.
The passive heave compensator system typically compensates through hydro-pneumatic action of compressing a volume of air and throttling of fluid via cylinders and pistons. As the rig heaves up or down, the set air pressure will support the weight corresponding to that pressure. As the drilling gets deeper and more weight is added to the drill string, more pressure needs to be added. A passive crown mounted heave compensator may consist of vertically mounted compression-type cylinders attached to a rigid frame mounted to the derrick water table, such as the Shaffer Crown Mounted Compensator also available from National Oilwell Varco of Houston, Tex. Both the in-line and crown mounted heave compensators use either hydraulic or pneumatic cylinders that act as springs supporting the drill string load, and allow the top of the drill string to remain stationary as the rig heaves. Passive heave compensators may be only about 45% efficient in mild seas, and about 85% efficient in more violent seas, again while the drill bit is on bottom and drilling.
An active heave compensator may be a hydraulic power assist device to overcome the passive heave compensator seal friction and the drill string guide horn friction. An active system may rely on sensors (such as accelerometers), pumps and a processor that actively interface with the passive heave compensator to maintain the weight needed on the drill bit while on bottom and drilling. An active heave compensator may be used alone, or in combination with a passive heave compensator, again when the drill bit is on bottom and the drill string is rotating for drilling. An active heave compensator is available from National Oilwell Varco of Houston, Tex.
A downhole motion compensator tool, known as the Subsea Downhole Motion Compensator (SDMC™) available from Weatherford International, Inc. of Houston, Tex., has been successfully used in the past in numerous milling operations. SDMC™ is a trademark of Weatherford International, Inc. See DURST, DOUG et al, “Subsea Downhole Motion Compensator: Field History, Enhancements, and the Next Generation,” IARC/SPE 59152, February 2000, pages 1-12, © 2000 Society of Petroleum Engineers Inc. The authors in the above technical paper IADC/SPE 59152 report that although semisubmersible drilling vessels may provide active rig-heave equipment, residual heave is expected when the seas are rough. The authors propose that rig-motion compensators, which operate when the drill bit is drilling, can effectively remove no more than about 90% of heave motion. The SDMC™ motion compensator tool is installed in the work string that is used for critical milling operations, and lands in or on either the wellhead or wear bushing of the wellhead. The tool relies on slackoff weight to activate miniature metering flow regulators that are contained within a piston disposed in a chamber. The tool contains two hydraulic cylinders, with metering devices installed in the piston sections. U.S. Pat. Nos. 6,039,118 and 6,070,670 propose downhole motion compensator tools.
Riser slip joints have been used in the past to compensate for the vertical movement of the floating rig on the riser, such as proposed in FIG. 1 of both U.S. Pat. Nos. 4,282,939 and 7,237,623. However, when a riser slip joint is located within the “pressure vessel” in the riser below the RCD, its telescoping movement may result in fluctuations of wellbore pressure much greater than 350 psi that are in harmony with the frequency and magnitude of the rig heave. This creates problems with MPD in formations with narrow drilling windows, particularly with the CBHP variation of MPD.
The above discussed U.S. Pat. Nos. 3,976,148; 4,282,939; 4,291,772; 4,355,784; 4,488,703; 4,508,313; 4,519,577; 4,626,135; 5,213,158; 5,647,444; 5,662,181; 5,735,502; 5,960,881; 6,039,118; 6,070,670; 6,138,774; 6,470,975; 6,913,092; 7,044,237; 7,159,669; 7,237,623; 7,258,171; 7,278,496; 7,367,411; 7,448,454; 7,487,837; and 7,650,950; and Pub. Nos. US 2006/0144622; 2006/0157282; 2008/0210471; and 2009/0139724; and International Pub. Nos. WO 2007/092956 and WO 2009/123476 are all hereby incorporated by reference for all purposes in their entirety. U.S. Pat. Nos. 5,647,444; 5,662,181; 6,039,118; 6,070,670; 6,138,774; 6,470,975; 6,913,092; 7,044,237; 7,159,669; 7,237,623; 7,258,171; 7,278,496; 7,367,411; 7,448,454 and 7,487,837; and Pub. Nos. US 2006/0144622; 2006/0157282; 2008/0210471; and 2009/0139724; and International Pub. No. WO 2007/092956 are assigned to the assignee of the present invention.
A need exists when drilling from a floating drilling rig for an approach to rapidly compensate for the change in pressure caused by the vertical movement of the drill string or other tubular when the rig's mud pumps are off and the drill string or tubular is lifted off bottom as joint connections are being made, particularly in moderate to rough seas and in geologic formations with narrow drilling windows between pore pressure and fracture pressure. Also, a need exists when drilling from floating rigs for an approach to rapidly compensate for the heave induced pressure fluctuations when the rig's mud pumps are off, the drill string or tubular is lifted off bottom, the annular BOP seal is closed, and the drill string or tubular nevertheless continues to move up and down from wave induced heave on the rig while riser gas is circulated out. Also, a need exists when tripping the drill string into or out of the hole to optimize tripping speeds by canceling the rig heave-related swab-surge effects. Finally, a need exists when drilling from floating rigs for an approach to rapidly compensate for the heave induced pressure fluctuations when the rig's mud pumps are on, the drill bit is on bottom with the drill string or tubular rotating during drilling, and a telescoping joint in the riser located below an RCD telescopes from the heaving.